NewEnergyNews

Gleanings from the web and the world, condensed for convenience, illustrated for enlightenment, arranged for impact...

While the OFFICE of President remains in highest regard at NewEnergyNews, this administration's position on the climate crisis makes it impossible to regard THIS president with respect. Below is the NewEnergyNews theme song until 2020.

Achieving the U.S. Department of Energy’s SunShot Initiative cost targets could greatly accelerate deployment of grid-integrated solar technologies. Global experience with increasing amounts of wind and solar on power systems has shown that variable generation resources can be integrated into the grid at penetrations well beyond current capacity. However, the prospect of dramatically increased photovoltaic (PV) deployment requires detailed examination to ensure that high-penetration solar technologies will provide their intended benefits, including reducing fossil fuel use and reducing the conventional capacity needed for reliable service. This report examines several aspects of how the bulk power system (consisting of traditional generators and the high-voltage transmission network) may need to evolve to accommodate the increased PV penetration resulting from achievement of the SunShot cost targets.

The characteristics of PV-generated electricity—including variability, uncertainty, and nonsynchronous generation—present challenges to large-scale, cost-effective grid integration by reducing PV’s energy value (and thus its ability to displace fossil fuel use) and capacity value (and thus its ability to replace conventional capacity). One challenge to realizing the full energy value of PV is the need to accommodate the changing net load (normal load minus generation from variable solar and wind sources) associated with high midday PV generation and low electricity demand. This situation can create “overgeneration,” when conventional dispatchable resources cannot be backed down further to accommodate the supply of PV and other variable generation (VG). Because of the threat of system disruptions from power supply exceeding demand, system operators might curtail PV output and thus reduce the economic and environmental benefits of PV energy. Similarly, the net load changes due to high PV penetration reduce PV’s ability to displace conventional generation capacity during high-demand periods.

Accommodating the changes in net load resulting from increased VG penetration requires enhancements to a power system’s “flexibility,” or the ability of the grid and generation fleet to balance supply and demand over multiple time scales. Numerous technologies and strategies for increasing flexibility have been implemented already, are being implemented today, or are being developed. These approaches allow VG to be used directly to offset demand and increase instantaneous VG penetration, or they improve the alignment of VG supply and demand. We describe six of these flexibility options: • System operation—Changing the way the grid is scheduled and dispatched, including changes to market rules, does not require new technologies and often represents the “least cost” way to aid VG integration.

• Flexible generation—Generators can respond better to the net load shape created by additional PV via increased ramp rates and ranges as well as the ability to start and stop more frequently.

• Reserves and stability services from VG—Inverter-based wind and solar plants can provide the grid’s frequency response needs as these plants become a larger proportion of the generation fleet and new mechanisms are developed.

• Transmission and coordination—Balancing supply and demand over larger areas reduces net variability of both load and renewable resources such as PV owing to greater spatial diversity of VG resources.

Deploying such grid-flexibility options can increase the energy and capacity value of PV to the grid. We use grid simulations to examine the impact of “near term” flexibility options in California, likely the first large region in the U.S. to experience significant impacts of PV on the transmission network; for this reason, we use California as a case study to examine how flexibility effects cost-effective integration of solar resources. Lessons learned from this region may assist other regions in developing strategies to mitigate the impacts of variability and uncertainty of the solar resource. Figure ES-1 demonstrates the levelized cost of energy (LCOE) from PV in California under two scenarios. The first is a limited-flexibility scenario, which reflects many historical grid operation practices that restrict participation of PV and other distributed resources in participation of grid services. The second is an enhanced-flexibility scenario which includes several grid-management techniques and technologies that will be or could be deployed by 2020. The base cost of PV assumes achievement of the SunShot target of 6 ¢/kWh as well as zero curtailment. The figure shows the steep increase in marginal PV LCOE (the incremental cost of an added unit of PV energy) due to curtailment at penetrations beyond about 10%. Marginal costs are particularly important when comparing PV to other generating options—by the time PV provides 20% of annual electricity demand, marginal curtailmentrelated costs erase the benefits of achieving the SunShot targets. The figure also shows, however, that flexibility enhancements can minimize curtailment and keep PV competitive at penetrations at least as high as 25%. Similarly, flexibility options such as demand response and energy storage can mitigate declines in capacity credit by exploiting how PV reduces the length of peak demand periods while also reducing the time between on- and off-peak periods.

Looking beyond the 2020 timeframe, our analysis shows how energy storage could facilitate the cost-effective integration of even higher PV penetration. Figure ES-2 shows the marginal curtailment curve when concentrating solar power (CSP) with thermal energy storage (TES) is added to a system with significant PV. In this case, CSP is added starting when solar provides about 28% of total demand and marginal curtailment of PV is 30%. Adding significantly more PV to this system will produce very high curtailment (greater than 50%). The dashed line shows the transition to the addition of CSP with TES. Adding a unit of CSP with 6 hours of TES and enough capacity to provide about 1% of additional solar generation will reduce marginal curtailment to about 10%, and this value could be lower with greater amounts of TES. This is one of many possible deployment scenarios—a more comprehensive analysis of renewable portfolios and flexibility options would help with determining the most cost-effective mix of technologies and strategies.

Clearly, implementation of appropriate flexibility resources is critical to making high-penetration PV part of a reliable, cost-effective, and low-carbon electric power system. This includes ensuring generation resources on the grid are committed and dispatched economically, with the ability to respond to variations in net demand. Operating the generation fleet in the most economic manner will unlock inherent flexibility in the system. Such insights will increase the value of solar generation in terms of both energy and capacity.

Orderly and economic deployment of flexibility options will require a variety of stakeholder actions, including new market rules and mechanisms. Distributed resources, including rooftop PV and distributed storage, must be made visible to system operators, and operators might need the ability to control the output of these resources to maintain a reliable grid. Updated grid codes and use of existing technologies such as smart inverters will allow PV to participate in system dispatch and the maintaining of grid frequency and voltage. Accelerating the participation of demand loads in providing grid services can further accelerate cost-effective integration of solar resources. Finally, storage technologies, including CSP with TES, can drive solar technologies toward SunShot-level deployment and beyond—enabling solar to become a primary component of the de-carbonized electricity future…

More than a decade of experience with wind integration in the United States, along with growing international solar-integration experience, has demonstrated the ability to cost effectively integrate VG resources into the nation’s electricity generation and transmission systems. A critical aspect of VG integration is recognizing and implementing cost-effective flexibility resources. This includes ensuring generation resources on the grid are committed and dispatched economically, with the ability to respond to variations in net demand. Operating the generation fleet in the most economic manner will unlock inherent flexibility in the system.

Such insights will increase the value of solar generation in terms of both energy and capacity. Increased operator experience with solar, improved forecasting, and new market flexibility products will also reduce the need for excessive and costly regulating reserves that may prevent full use of solar resources. Increasingly, recognition that solar and wind must be integral parts of the electricity system, actively providing multiple grid services, will also decrease dependence on traditional generators for reserves and grid-stability services.

Orderly and economic development and deployment of flexibility options will require a variety of stakeholder actions. While many flexibility options are currently being deployed, others will require new market rules and mechanisms. Economic integration of widespread solar will require that distributed resources, including rooftop PV and distributed storage, be visible to system operators, and it may require operators to control their output to maintain grid stability. Updated grid codes and use of existing technologies such as smart inverters will allow PV to participate in system dispatch and the maintaining of grid frequency and voltage. The natural evolution of markets—including increased, cost-effective responsiveness of demand more variable grid conditions—will also create new opportunities to integrate solar. Finally, multiple storage technologies now being deployed or under development, including CSP with TES, can drive solar technologies toward SunShot-level deployment and beyond—making solar a primary component of the de-carbonized electricity future.

QUICK NEWS, May 31: Climate Change Preparation Shifts Power To Locals; First U.S. Ocean Wind About To Turn On; Potential Geothermal Buy-Ins

“…[Federally funded teams are attempting to learn from [failed urban projects] as they try to protect low-income communities from storm surges and heat waves as the climate continues to change and weather becomes more destructive…To ensure that communities went all-in for [its Rebuild by Design projects started after Hurricane Sandy, the federal Department of Housing and Urban Development] upended the normal infrastructure process: Instead of deciding what to build, municipal governments have to earn federal money by presenting ideas developed in close consultation with civic groups representing coastal communities from Connecticut to New Jersey…When the waters subsided, a coalition of 38 groups—including [Lower East Side] residents’ associations, advocacy groups, resource-rich charities like the Red Cross and corporate sponsors like Whole Foods Market—came together asLES Readyto organize immediate aid and develop long-term plans to better prepare the area for future environmental disasters…This approach is a trend around the world…”click here for more

“The first offshore wind farm in the [U.S., Deepwater Wind’s 30 MW Block Island project off Rhode Island, will] begin delivering power to Rhode Island’s electricity grid by year’s end, a milestone that could help reshape energy markets from New England to South Florida, experts say…[T]o achieve its full potential, as much as 4 gigawatts of capacity, it will need a major influx of capital and know-how, much of which will come from Europe, where the technology has a 25-year performance record and now accounts for 11 GW of generation capacity on the continent…[Leaders say the] industry should act now to establish the technical, logistical and policy frameworks to build more offshore wind farms…[including] setting up domestic supply chains to serve offshore regions and training a skilled workforce to deploy into the offshore wind environment [that could support hundreds of turbines by 2025]…”click here for more

“…[There are only two pure geothermal plays listed on major exchanges: Polaris Infrastructure (OTCPK:RAMPF) and U.S. Geothermal Inc (NYSEMKT:HTM)…[In 2015, Polaris restructured, reduced] its debt load, issued new shares and changed its management…[It’s one operating plant, San Jacinto in Nicaragua, has a stable] operating revenue of roughly $50 million…[from a contract that] expires in 2029…[The company claims one megawatt of power is equal to $1 million in the annual EBITDA…[U.S. Geothermal operates three [U.S. geothermal plants, two of which are outperforming and one underperforming. The three operating power plants are a source of stable income and cash flows. However, a big part of these earnings and cash flows is utilized by non-controlling interests - earnings and cash flows by Enbridge…and tax credits by Goldman Sachs…[leaving little for] shareholders…Increasing the EBITDA attributable to US Geothermal shareholders from today's $10 million to $16 million could transition US Geothermal into a dividend-paying company…”click here for more

Monday, May 30, 2016

TODAY’S STUDY: The Solar Boom Nurtured by President Obama

The SunShot Initiative’s original targets were set in terms of reduced solar technology prices and electricity costs, which detailed analysis suggests will translate into dramatically higher U.S. solar deployment over the next several decades. The cost of solar electricity in dollars per kilowatt-hour ($/kWh) can be reduced by boosting the amount of energy a solar system produces over its lifetime (kWh), cutting the lifetime cost ($) of that system, or both. Once that cost is at or below the cost of competing energy technologies, solar deployment should proceed rapidly. This is valid, to a point, and has been reflected in market developments to date.

However, as U.S. solar electricity has continued its transformation from a niche to the mainstream, several challenges to this equation have become increasingly clear. First, the cost of a solar system embraces more than the cost of solar hardware and even more than the cost of the various processes required to sell, install, and interconnect the system. Second, solar’s cost is dynamically intertwined with the characteristics and costs of all the other ways of satisfying electricity demand within the power system. Finally, some kWhs of solar electricity may be more useful than others—and more useful to some stakeholders than to others—which can have profound implications for cost. All these observations are linked by the concept of value. Value encompasses solar electricity’s costs and benefits. For example, solar electricity might have one set of costs and benefits to a homeowner, another to a utility, and yet another to the broader society. It might have more value than natural gas-generated electricity in one time, place, and mix of generating technologies but less value in a different situation. And so forth.

Failure to address this complex web of value-related issues could jeopardize the SunShot Initiative’s vision of affordable, widely deployed solar that produces substantial national benefits, including a boost to U.S. solar manufacturing. Conversely, effectively weaving the threads together could spur achievements that surpass the original SunShot vision. Here we extract insights from the On the Path to SunShot reports to highlight critical connections that affect solar costs, deployment, and domestic manufacturing. We also highlight some of the SunShot Initiative’s activities that are supporting advances in key areas. Amid the complexity, one common theme emerges—sustained, multifaceted innovation will be needed to achieve the solar future.

Increasing the use of grid-flexibility options (improved grid management, demand response, and energy storage) could enable 25% or higher penetration of PV at low costs (see Denholm et al. 2016). Considering the large-scale integration of solar into electric-power systems complicates the calculation of the value of solar. In fact a comprehensive examination reveals that the value of solar technologies—or any other power-system technology or operating strategy—can only be understood in the context of the generation system as a whole. This is well illustrated by analysis of curtailment at high PV penetrations within the bulk power and transmission systems. As the deployment of PV increases, it is possible that during some sunny midday periods due to limited flexibility of conventional generators, system operators would need to reduce (curtail) PV output in order to maintain the crucial balance between electric supply and demand. As a result, PV’s value and cost competitiveness would degrade. For example, for utility-scale PV with a baseline SunShot LCOE of 6¢/kWh, increasing the annual energy demand met by solar energy from 10% to 20% would increase the marginal1 LCOE of PV from 6¢/kWh to almost 11¢/kWh in a California grid system with limited flexibility. However, this loss of value could be stemmed by increasing system flexibility via enhanced control of variable-generation resources, added energy storage, and the ability to motivate more electricity consumers to shift consumption to lower-demand periods. The combination of these measures would minimize solar curtailment and keep PV cost-competitive at penetrations at least as high as 25%. Efficient deployment of the grid-flexibility options needed to maintain solar’s value will require various innovations, from the development of communication, control, and energy storage technologies to the implementation of new market rules and operating procedures.

Wide use of advanced inverters could double the electricity-distribution system’s hosting capacity for distributed PV at low costs—from about 170 GW to 350 GW (see Palmintier et al. 2016). At the distribution system level, increased variable generation due to high penetrations of distributed PV (typically rooftop and smaller ground-mounted systems) could challenge the management of distribution voltage, potentially increase wear and tear on electromechanical utility equipment, and complicate the configuration of circuit-breakers and other protection systems—all of which could increase costs, limit further PV deployment, or both.2 However, improved analysis of distribution system hosting capacity—the amount of distributed PV that can be interconnected without changing the existing infrastructure or prematurely wearing out equipment—has overturned previous rule-of-thumb assumptions such as the idea that distributed PV penetrations higher than 15% require detailed impact studies. For example, new analysis suggests that the hosting capacity for distributed PV could rise from approximately 170 GW using traditional inverters to about 350 GW with the use of advanced inverters for voltage management, and it could be even higher using accessible and low-cost strategies such as careful siting of PV systems within a distribution feeder and additional minor changes in distribution operations. Also critical to facilitating distributed PV deployment is the improvement of interconnection processes, associated standards and codes, and compensation mechanisms so they embrace PV’s contributions to system-wide operations. Ultimately SunShot-level PV deployment will require unprecedented coordination of the historically separate distribution and transmission systems along with incorporation of energy storage and “virtual storage,” which exploits improved management of electric vehicle charging, building energy systems, and other large loads. Additional analysis and innovation are needed in every area to realize the potential of this integrated vision.

Although tremendous progress has been made in reducing the cost of PV systems, additional LCOE reductions of 40%–50% between 2015 and 2020 will be required to reach the SunShot Initiative’s targets (see Woodhouse et al. 2016). Understanding the tradeoffs between installed prices and other PV system characteristics—such as module efficiency, module degradation rate, and system lifetime—are vital. For example, with 29%-efficient modules and high reliability (a 50-year lifetime and a 0.2%/ year module degradation rate), a residential PV system could achieve the SunShot LCOE goal with modules priced at almost $1.20/W. But change the lifetime to 10 years and the degradation rate to 2%/year, and the system would need those very highefficiency modules at zero cost to achieve the same LCOE. Although these examples are extreme, they serve to illustrate the wide range of technological combinations that could help drive PV toward the LCOE goals. SunShot’s PV roadmaps illustrate specific potential pathways to the target cost reductions.
Energy storage will help enable CSP compete by adding flexibility value to a high-variable-generation (solar plus wind) power system (see Mehos et al. 2016). Compared with PV, CSP systems are more complex to develop, design, construct, and operate, and they require a much larger minimum effective scale—typically at least 50 MW, compared with PV systems that can be as small as a few kilowatts. In recent years, PV’s greater modularity and lower LCOE have made it more attractive to many solar project developers, and some large projects that were originally planned for CSP have switched to PV. However, the ability of CSP to use thermal energy storage—and thus provide continuous power for long periods when the sun is not shining—could give CSP a vital role in evolving electricity systems. Because CSP with storage can store energy when net demand3 is low and release that energy when demand is high, it increases the electricity system’s ability to balance supply and demand over multiple time scales. Such flexibility becomes increasingly important as more variable-generation renewable energy is added to the system. For example, one analysis suggests that, under a 40% renewable portfolio standard in California, CSP with storage could provide more than twice as much value to the electricity system as variable-generation PV. For this reason, enhanced thermal energy storage is a critical component of the SunShot Initiative’s 2020 CSP technology-improvement roadmap.

Innovation-driven cost and performance improvements, along with strong projected solar demand in the United States and across the Americas, could increase the attractiveness of U.S.-based solar manufacturing (see Chung et al. 2016). Although improvements to standard PV modules have produced deep cost reductions over the past 5 years, the returns on such incremental improvements appear to be diminishing, and more dramatic innovations in module design and manufacturing are required to continue along the path of rapid progress. At the same time, major opportunities exist for innovation to unlock the potential of CSP technologies. This need for innovation could benefit U.S. PV and CSP manufacturers. The United States has been rated one of the world’s most competitive and innovative countries as well as one of the best locations for PV manufacturing. It is a global leader in PV and CSP R&D and patent production, and U.S. PV manufacturers are already pursuing highly differentiated innovations.

Financial innovations—independent of technology-cost improvements—could cut the cost of solar energy to customers and businesses by 30%–60% (see Feldman and Bolinger 2016). Financing is critical to solar deployment, because the costs of solar technologies are paid up front, while their benefits are realized over decades. Solar financing has been shaped by the government incentives designed to accelerate solar deployment. This is particularly true for federal tax incentives, which have spawned complex tax-equity structures that monetize tax benefits for project sponsors who otherwise could not use them efficiently. Although these structures have helped expand solar deployment, they are relatively costly and inefficient. This has spurred solar stakeholders to develop lower-cost financing solutions such as securitization of solar project portfolios, solar-specific loan products, and methods for incorporating residential PV’s value into home values. To move solar further toward an unsubsidized SunShot future, additional financial innovation must occur. Development of a larger, more mature U.S. solar industry will likely increase financial transparency and investor confidence, which in turn will enable simpler, lower-cost financing methods. Utilityscale solar might be financed more like conventional generation assets are today, non-residential solar might be financed more like a new roof, and residential solar might be financed more like an expensive appliance. Assuming a constant, SunShot-level installed PV system price, such financing innovations could reduce PV’s LCOE by an estimated 30%–60% (depending on the sector) compared with historical financing approaches.

Implementing a range of alternative utility-rate reforms could minimize solar value losses at increasing levels of distributed PV penetration (see Barbose et al. 2016). In conjunction with the technical issues described above, the connections between distributed PV and electric distribution systems hinge on utility business models and regulations. As PV deployment has leapt forward and presaged a truly significant solar contribution, however, it has become clear that utilities’ traditional treatment of distributed PV cannot be taken for granted—nor can the future value and deployment of distributed PV. At the heart of this issue is net energy metering (NEM). Under NEM, PV owners can sell to a utility the electricity they generate but cannot consume on site, often at full retail rates. This widespread policy has helped drive the rapid growth of distributed PV, but the success has raised concerns about the potential for higher electricity rates and cost-shifting to non-solar customers, reduced utility shareholder profitability, reduced utility earnings opportunities, and inefficient resource allocation. The resulting reform efforts have revolved largely around changing NEM rules and retail rate structures. Most of the reforms to date address NEM concerns by reducing the benefits provided to distributed PV customers and thus constraining PV deployment. A new analysis estimates that eliminating NEM nationwide, by compensating exports of PV electricity at wholesale rather than retail rates would cut cumulative distributed PV deployment by 20% in 2050 compared with a continuation of current policies. This would slow the PV cost reductions that arise from larger scale and market certainty. It could also thwart achievement of the SunShot deployment goals even if the initiative’s cost targets are achieved. This undesirable prospect is stimulating the development of alternative reform strategies that address concerns about distributed PV compensation without inordinately harming PV economics and growth.

Monetizing the environmental health benefits of solar could add ~3.5¢/kWh to the value of solar energy (see Wiser et al. 2016). The monetary impacts due to environmental degradation and public health impacts seem far removed from the apparent “sticker price” of electricity. Yet quantifying these impacts is essential to understanding the true costs and benefits of solar and conventional generating technologies. Compared with fossil fuel generators, PV and CSP produce far lower lifecycle levels of greenhouse gas (GHG) emissions and harmful pollutants including fine particular matter (PM2.5), sulfur dioxide (SO2), and nitrogen oxides (NOx). Achieving the SunShot-level solar deployment targets—14% of U.S. electricity demand met by solar in 2030 and 27% in 2050—could reduce cumulative power-sector GHG emissions by 10% between 2015 and 2050, resulting in savings of $238–$252 billion.4 This is equivalent to 2.0–2.2 cents per kilowatt-hour of solar installed (¢/kWh-solar). Similarly, realizing these levels of solar deployment could reduce cumulative power-sector emissions of PM2.5 by 8%, SO2 by 9%, and NOx by 11% between 2015 and 2050. This could produce $167 billion in savings from lower future health and environmental damages, or 1.4¢/kWh-solar—while also preventing 25,000–59,000 premature deaths. To put this in perspective, the estimated 3.5¢/kWh-solar in benefits due to SunShot-level solar deployment is approximately equal to the additional LCOE reduction needed to make unsubsidized utility-scale solar competitive with conventional generators today. In addition, water savings from achieving the SunShot goals, could result in the 2015–2050 cumulative savings of 4% of total power-sector withdrawals and 9% of total power-sector consumption—a particularly important consideration for arid states where substantial solar will be deployed. Improving public health and the environment is but one aspect of solar’s many costs and benefits. Clearly, however, the assignment of value to such “external” impacts has potential implications for policy innovation and the economic competitiveness of solar and other generation technologies.

QUICK NEWS, May 30: What New Energy Means To The Military; How New Energy Saves Military Lives; Arnold Talks Climate To The Troops

“Memorial Day reminds us that those in the military serve and sacrifice every day to keep our nation strong…[and] the military’s work to address the effects of climate change and to advance energy security is a critical part of that strength…[In the 2014 Quadrennial Defense Review, the U.S. Department of Defense] identified climate change as a key security risk facing our nation as well as those around the world…The Department of Homeland Security and top-ranking intelligence community officials agree with the DoD’s assessment…[The recently films The Age of Consequences and The Burden also highlight] the role of climate change impacts in driving resources scarcity such as drought and famine, which then in turn fuel [armed conflict, the depletion of military resources, and lost lives. The] Department of Defense has adopted a goal to source 25 percent of its energy from renewable sources by 2025, while the Department of the Navy is seeking 50 percent by 2020. The Navy has installed about one gigawatt of solar already…”click here for more

“…[The U.S. military is known] for its bravery but it’s now also known for its use of green energy, battery storage and microgrids — that is saving the lives of soldiers in the battle field while also producing cleaner energy…[T]he Defense Department has set a lofty goal for itself to consume 3,000 megawatts from renewable sources by 2025…[and getting] there is an imperative, given that it is now spending $4 billion annually to power its current installations and operations…

"The major costs are the logistics associated with moving the generators and fuels — items that could eventually be displaced with 21st Century technologies…The military, in fact, is the world’s most voracious consumer of energy. But specifically, it is using fossil fuels on the battlefield that can run low and put people at risk. By carrying sustainable sources of power with them, soldiers are reducing their risks — while also creating fewer emissions…”

“…Arnold Schwarzenegger visited U.S. soldiers in Kuwait late last month, stopping by camps Arifjan and Buehring to film parts of ‘Years of Living Dangerously,’ a documentary series that will air on the National Geographic Channel in October…[During the workout, he lifted weights with some troopers and talked about] some of Army Central's work toward cleaner energy use, including modular building materials with increased insulation that keeps down power costs, the replacement of diesel-powered light towers with solar power, and a solar-powered, off-the-grid network that can provide the energy needed to run small facilities within a camp…[He also] participated in 10 promotions and one re-enlistment…”click here for more

"You Can’t Keep Doing Things The Way You Did"

This guy isn’t a leftie tree-hugger, he is the guy responsible for keeping California’s lights on and he says the grid can reliably and safely handle over 50% New Energy “and beyond.” From AmericanWindEnergy via YouTube

For utilities and system operators who find that coping with all the new distributed resources on the grid is like holding an armful of marbles, you may have a new — and rather unexpected — best friend: SolarCity.

The leading U.S. solar installer’s new white paper, "Integrated Distribution Planning," aims to get all the new grid resources and their uses organized so they can be put to the best use by power companies and system operators.

The assets are distributed energy resources (DERs), which include distributed renewables like rooftop solar as well as advanced inverters, stationary energy storage, electric vehicles, and technologies that allow for demand flexibility — the ability of utility customers to control their electricity use and participate in energy efficiency and demand response programs.

Programs for individual DERs at utilities “have been successful and pushed engagement,” Hanley said. “But that approach limits the true capability of these assets. As an aggregate portfolio of multiple assets, these diverse assets accommodate for their individual weaknesses and become more powerful.”

By modernizing utility interconnection, planning, procurement, and data sharing processes, utilities and distribution system operators can capture the benefits of DERs in bundles to both meet distribution needs and expand customer choice, the white paper explains.

The idea to aggregate was put forward some months ago by former Texas utility executive and utility commissioner Karl Rabago.

“The time has come to complete the transformation of the electric utility sector,” he wrote in a blog post in February. “A deliberate and sustained effort to establish robust markets for distributed energy services is the major remaining step in that process.”

“It is imperative to transition to a grid that actively leverages the wave ofrenewable distributed energy resources,” Hanley’s paper explains, because it is a way of “engaging customers in energy management, increasing the use of clean renewable energy, improving grid resiliency, and making the grid more affordable by reducing system costs.”

How the new responsive grid would work

Under the paradigm of distribution system planning that Hanley and his colleagues are pushing, utilities could meet system needs with aggregations of distributed resources, put together by companies like SolarCity.

“Today, a utility thinks of control as a fiber line going directly to a generator,” Hanley said. “In the future, a utility controls our assets through an interface at a substation.”

Under that system, the utility communicates its need through the interface in grid terms, asking for capacity or reactive power or another ancillary service. SolarCity or another supplier commits to meet the need and then uses aggregated DERs in the region served by the substation to meet the utility's demands.

“We don’t tell the utility how we will do it because every day it will probably be a little different,” Hanley said.

SolarCity would look for the most economic portfolio of assets to meet any given utility need. One day it might be part pre-contracted reduced customer consumption, part reimbursed customer consumption cuts, and part purchased energy from batteries. Another day it might include solar from roofs where customers are not home, or power from parked electric vehicles as well as reduced consumption.

“The utility gets what it needs every single time because we have a firm contract to deliver,” Hanley said. “The way we make money is getting good at optimization, at making sure our assets are available.”

Utilities would need to be no more concerned about SolarCity fulfilling its “contract to deliver” than they now are about central station power plants meeting their obligations, Hanley said. “The key is to make the financial disincentive so punitive that people show up. We are ready for that.”

DERs can support the grid, and in many ways do it better than the assets now available, he added.

“The premature retirement of the San Onofre Nuclear Generating Station cost Southern California ratepayers over $3 billion," Hanley said. "With distributed resources, there is never one big asset that fails. There will be small ones that fail, but having a stranded cost of over $3 billion would not happen.”

Rabago applauded SolarCity’s attention to DERs and the distribution systembecause it meets the “glaring absence of adequate, comprehensive, integrated distribution planning.” But, he reminded, “you still have to plan for the rest of the system.”

The Distribution Loading Order

To modernize procurement for the distribution system, the white paper offers its biggest innovation.

System needs are today met through procurement of “utility-owned distribution equipment such as transformers, capacitor banks, reconductored wires, and other capital equipment,” it says.

In a high DER penetration future, “distribution planners must be willing and able to consider the full range of solutions,” the paper says. To lead planners there, the paper proposes a new distribution-level policy concept to encourage utilities to use DERs instead of traditional energy solutions when they are cost effective. It's called the Distribution Loading Order.

Some states have a system level loading order. California, Hanley noted, requires its regulated utilities to consider energy efficiency first, followed by demand response, and then renewables and distributed generation, before the grid operator can look to traditional generation.

“This procurement loading order puts the traditional ‘least cost, best fit’ solution in the ground,” Hanley said. Efficiency, demand response, and renewables are bypassed if they are not price competitive. “If fossil fuels are the cheapest, they get picked.”

Similarly, SolarCity’s loading order “prioritizes the utilization of individual DERs or portfolios of DERs over traditional utility infrastructure, when such portfolios are cost-effective and able to meet grid needs,” the paper reports.

The idea is to “use DERs before traditional capital grid investment if DERs are cheaper than or the same price as doing a substation upgrade,” Hanley said. “If DERs are not cheaper, pick the upgrade.”

Utilities and distribution system operators should consider two DER opportunities before turning to hardware, according to the paper. First, are “DER portfolios that voluntarily respond to price signals sent from the utility that incent the desired behavior to meet grid needs.”

SolarCity customers with solar-plus-storage, smart thermostats and meters could readily respond to price signals to alter their usage when system demand peaks, Hanley said. “If utilities do substation upgrades, they won’t use these low marginal cost resources.”

If those DERs do not meet the “least cost, best fit” standard, procurers should turn to “DER portfolios that are contractually obligated to deliver grid services based on contracted prices.”

Only if planners conclude these options cannot meet system needs should they turn to hardware upgrades, Hanley said. “This extends the tool kit utilities have to meet their distribution system needs, and if they follow the economic principle of ‘least cost, best fit’ it also guarantees that ratepayers are getting the best solutions available.”

"We have long claimed to use 'economic dispatch' as the protocol,” he observed. “But best buys don’t actually go first. Rather, the system loads baseload to recover capacity costs, then continues to dispatch from least to most dispatchable.”

SolarCity’s loading order could be the needed protocol, he thought. But also needed at the system level is a “‘load management utility’ with performance standards rewarding maximum reliance on DER first, and then using large-scale resources only as necessary.”

The paper’s discussion on interconnection modernization comes down to a relatively simple idea that covers a lot of ground: “Streamline the DER interconnection process, eliminate unwarranted costs, and expand allowable interconnection approvals.”

The paper offers an array of granular improvements on ideas presented elsewhere, Hanley said, because, as the paper notes, “the pace of change is measured…[and] a more comprehensive set of enhancements is needed.”

A key improvement, it says, would be utilities incorporating “automated DER Hosting Capacity analyses into the interconnection review process to increase allowable interconnections while decreasing the application review timeline.”

“The extensive detail on interconnection will benefit all DER, and is long overdue,” Rabago said. “SolarCity has the national reach and visibility to add value to this discussion.”

The planning modernization section covers much of the same ground as the California Public Utilities Commission (CPUC) Distribution Resource Planning (DRP) proceeding but “we try to push that ahead,” Hanley said.

“The goal is to identify locational needs across the [distribution] grid, just like they do on the transmission grid," he said.

As the presence of DERs increases, customer choice must also be accommodated into grid needs, the paper reads.

“Utilities will need to become much more proficient at forecasting customer DER growth than they are today.” With a more detailed understanding of what is coming, it adds, planners will be able to find DER alternatives to procured investments “at low or no cost.”

The analysis should not be limited to technical capacity but should “be informed by economics,” Rabago said. “We need value-based analysis of DER so that best buys can go first…[and not] resources that offer suboptimal value.”

DER providers need operational and planning data to achieve optimization and drive innovation, but utilities make little of it available, the paper asserts. “Solely publishing outcomes of utility analyses rather than sharing the underlying data does not enable sufficient industry stakeholder engagement,” it reports.

There are five categories of data that utilities must commit to sharing, SolarCity believes:

-Locations where DERs would be of most value to the system

-The circuit by circuit capacity of the system

-Locations of planned investments in the system for which DERs may reduce the need

-Real-time and historical operational data that points to how DER portfolios can meet grid needs

-Pricing data and event statistics that would support transactive markets

To allow DER providers to serve the system, the paper says, utilities must make the data accessible online and downloadable. System maps made available by Southern California Edison and Pacific Gas & Electric in the CPUC’s Renewable Auction Mechanism program and the DRP proceeding are examples of data sharing that, while not perfect, are innovative, Hanley said.

The practice of utilities holding data unavailable to the market is part of an outdated business model, Hanley said.

“Companies that can crunch more data than the utilities have ever seen are on the sideline because they can’t get access,” he explained. “But it has been shown time after time that if you share data, innovation will accelerate and it is good for consumers.”

In the role of system support, SolarCity could send sales teams to circuits where there will be upgrades and avoid circuits without capacity.

“Utilities will say they can tell us where to install or the hosting capacity on a circuit and you don’t need the underlying data,” Hanley said. “But there will be new questions tomorrow that can only be answered by having the data.”

Rabago applauded the paper’s data and transparency discussion.

“This adds important detail to a discussion that is too often very generalized," he said. "It will also be a huge battleground.”

What the paper proposes “is a new paradigm and it will take time,” Hanley said. But utility engineers think about DERs like any technology and are becoming more comfortable with them every month.

"As DERs become cheaper, [utilities] will use more of the products," he said. "It is already reaching a tipping point.”

SPECIAL QUICK NEWS, May 27: Trump Twaddle On Wind Set Straight

AWEA is always glad to hear about support for renewable energy, like this statement today from candidate Donald Trump, in a press conference and a speech on energy policy to an oil industry group in Bismarck, North Dakota:

“So we can pursue all forms of energy. This includes renewable energies and the technologies of the future.”

Trump said that includes wind. However he then cited bad information that’s out-of-date, discredited, misleading, and just plain wrong, about the cost of wind, incentives to build turbines, and effects on eagles and birds.

Trump on the cost of wind energy: “Wind is very expensive, I mean wind is, without subsidy, wind doesn’t work.”

Actually: Wind is already cheaper than fossil fuels in wind-rich areas like Iowa and Texas, a statement Politifact checked and rated “True.” It’s increasingly cost-competitive not counting any incentives. The overall cost of wind-generated electricity has fallen 66 percent since 2009.

Trump on incentives: “You need massive subsidies for wind…The government should not pick winners and losers.”

Actually: All forms of energy have incentives, most of them permanent in the tax code. The only ones preparing to phase out their incentives are wind and the other renewable industries. The wind Production Tax Credit is set to phase out starting next year.

Trump on eagles: “…there are places maybe for wind. But if you go to various places in California, wind is killing all of the eagles.”

Actually: Publicly available data of all known eagle fatalities shows collisions with wind turbines at modern wind farms are responsible for less than five percent of all documented human-caused golden eagle deaths. Cases are even rarer of bald eagles striking turbines. The numbers of both kinds of eagle are increasing in the Western U.S.

Trump on birds: “Wind turbines kill far more than a million birds a year, far more…so wind is, you know, it’s a problem.”

Actually: Mr. Trump’s numbers are off by orders of magnitude. Wind power has among the lowest impacts on wildlife of any way to make electricity. Leading wildlife groups like the Audubon Society, the National Wildlife Federation, and the World Wildlife Fund support responsibility sited wind turbines. Wind energy is the low-cost solution to carbon pollution in particular which threatens all wildlife. Unlike all other human sources, the wind industry works to minimize and offset the limited impacts it has on individual birds, building on a legacy of care for birds and environment.

Trump ended by saying “Despite that, I am into all types of energy. And by the way, while we’re in North Dakota, I have to say that: I love the farmers.”
We encourage Mr. Trump to love the wind farmers, too. In most cases they’re the same people: 98 percent of wind turbines are erected on private land, leased from farmers and ranchers.

So the good news about wind energy is not just it’s good for consumers and the environment, it has also given the farmers in 40 states a valuable new cash crop, as it has in North Dakota.

Fresh from establishing the first national regulatory standards for carbon emissions earlier this month, President Obama has now joined the debate over the utility business model and called for a distributed, clean energy revolution.

The president took his commitment to the fight against climate change to new ground in a keynote address at the eighth annual Clean Energy Summit in Las Vegas, Nevada. His bold words reinforced the message delivered earlier in the day by Senator Harry Reid (D-NV), who also showed an unflagging commitment to renewables and a reformation of the utility business model.

“Earlier this month I unveiled our Clean Power Plan,” the president told a packed house at the Mandalay Bay Convention Center. “It is the first set of nationwide standards to end the limitless dumping of carbon pollution from our power plants and it is the single most important step America has ever taken to combat climate change.”

He repeated his now-familiar belief that “no challenge poses a greater threat to our future than climate change.”

But his administration holds another belief as well, he added.

“We are deeply optimistic about American ingenuity. We think we can do good and do well. We believe we have the power, the dynamism, and the creativity to solve a big problem while keeping the engines of the American economy moving.”

The president talked about his administration’s crucial investments, beginning with the 2009 Recovery Act — which he called the biggest commitment to renewables ever made — and carrying through to a just-announced $1 billion Department of Energy (DOE) commitment to new loan guarantees for distributed generation technologies.

That loan program was just one of multiple executive orders the White House released Monday ahead of Obama's speech, all looking to stimulate the growth and technological progression of distributed resources.

In line with his executive orders, the president aggressively advocated for higher penetrations of renewables like solar and wind, and reiterated that government investments that are needed to help make it happen.

“If we keep investing in wind rather than making mindless cuts chasing shortsighted austerity, wind could provide as much as 35% of America’s electricity and supply renewable power in all 50 states by 2050,” Obama said, taking a swipe at fiscal conservatives on behalf of wind energy’s production tax credit.

“America generates 20 times as much solar as we did in 2008,” President Obama said. And with a new solar array connected every three minutes, the solar industry last year added jobs 10 times faster than the rest of the economy, he said.

“Now is not the time to insist on massive cuts to investments that have helped drive our economy, including the hundreds of millions of dollars in cuts that many Republicans want to take from successful job-creating clean energy programs,” Obama said, “investments that have finally, in some places, made clean power from the sun cheaper than conventional power from utilities.”

It had to be a hard-to-hear message for NV Energy CEO Paul Caudill, who spoke just ahead of the president. His utility is in a tense face-off with Nevada solar advocates over its proposal to reduce the nationally embattled net energy metering policy crucial to the rooftop solar value proposition.

“NV Energy needs to get real,” Senator Reid, whose age and health make a 2016 Senate run unlikely, warned in a private session earlier in the day. “It is not 1888. Customers want choice. If NV Energy continues on this path, they will lose on the battlefield of public opinion and the courts will also ultimately decide they are wrong.”

It is impossible to overstate the significance of solar becoming price competitive with utility-provided electricity, the president said. “For decades we have been told it doesn’t make economic sense to switch to renewable energy. Today that is no longer true.”

He described big renewables buy-ins from major corporation such as Google, Apple, and Costco. “Walmart has the most installed onsite solar capacity of any company in America," he said. "They are not in the business of giving away money.”

The commitment of these companies should be cause for hope in the climate fight, he added, but to get to the renewables goals his administration has set, “we have to triple where we are today — so I am here to give you hope, but not complacency.”

He described a new initiative from DOE to fund the Property Assessed Clean Energy (PACE) program that will allow homeowners to obtain solar financing secured by their mortgages and repay the loan through their energy bill savings.

“It will allow more Americans to join this revolution with no money down,” Obama said. “You don’t have to share my passion for fighting climate change. Americans are going solar not because they are treehuggers, though trees are important, but because they are cost-cutters. Solar isn’t just for the green crowd anymore — it’s for the green eyeshade crowd, too.”

Solar is less than 1% of the U.S. energy mix and wind is only about 5%, but together they were over half of the new generation capacity built in 2014, the president said. “We see the trend lines. We see where technology is taking us, we see where consumers want to go.”

But fossil fuel interests, formerly unrestrained advocates of a free market, are suddenly opposed to choice in the marketplace because “solar is what people want to buy,” he smiled. “That’s a problem.”

The president acknowledged Tea Party members who, in joining a Green Tea Alliance with environmentalists, stayed true to their free market ideology. “This is not and should not be a Republican versus Democratic issue,” he said. “If you care about the future of our children and grandchildren, you should care about it.”

For decades, he explained, “utilities generated power, usually by burning fossil fuels, they ran lines to homes and businesses, and we paid for it. It wasn’t exciting. There wasn’t a lot of innovation. And we didn’t think about much about it until the bill came. And the economy grew under that model."

But that has all changed, the president said. With smart technologies, customers can understand their energy use, change their habits, use energy more efficiently, and save without great sacrifice.

“That empowers us to generate our own energy or store it in battery packs or sell it to the grid," he said. "That is power. That is the future. It is happening now. It is like evolving from the telegraph to the smart phone in less than a decade.”

The president commended the utilities that are adapting their business models “to seize the opportunities of this emerging reality.” He called outCPS Energy of San Antonio for its rooftop solar program, Southern Company for its partnership with Nest and Tesla on energy storage, and Oklahoma Gas & Electric for its smart meter rollout.

The rapid change is also drawing protective resistance from “some fossil fuel interests” dedicated to an “outdated status quo,” he said. But utility CEOs may have found solace in the president’s call for addressing “legitimate issuesaround how a new distributed system can work and how to deal with the costs.”

There is no legitimacy, however, in “massive lobbying efforts backed by fossil fuel interests or conservative think tanks or the Koch brothers” against consumers’ rights to choose renewables, the president said. “That is not the American way. That is not progress. That is not innovation.”

Obama echoed Senator Reid’s earlier attack on NV Energy. “The utility business model made sense a long time ago,” Reid said. “But today consumers would rather pay to make their homes more efficient than for utility electricity.”

Utilities thinking of clean energy as a burden,” Reid said, makes as much sense as the Washington Nationals benching star player Bryce Harper. “Utilities must not have a stodgy commitment to the status quo. They must seize the clean energy opportunity or consumers will suffer.”

President Obama framed the fight over energy as a question of whether the “big polluters” control the system or consumers have the “freedom to choose,” pitting “old ways” against new business models.

“This is about the past versus the future and America believes in the future," Obama said. "But to make that future real, we have to have everyone: Utilities, entrepreneurs, workers, businesses, consumers, energy regulators, treehuggers, Tea Partiers. Everybody has to seize the opportunities before us.”

Some utilties that have chose to disrupt themselves have already moved in the direction the president and Senator Reid described. In particular their comments fall in line with NRG Home’s organizing principle, as described recently to Utility Dive by CEO Steve McBee.

“The company’s strategy, value proposition, and value creation are aimed at figuring out what the customer wants,” McBee explained. Companies that don’t understand what is happening are struggling, while companies that are empowering consumers are seeing success.

“There is something big happening in America,” President Obama said. “For the first time we can actually see what our clean energy future looks like.” If the opposition claims it is a bad thing, “we have to be able to politely but firmly say ‘Sorry, we are moving forward.’”

It is “an age old debate in America between the folks who say ‘No we can’t’ and the folks who say ‘Yes we can,’” Obama said. “America always comes down on the side of the future. We have always been a people who reach, proudly and boldly and unafraid, to that more promising future. We refuse to surrender the hope of a clean energy future to those who fear it and fight it. And sometimes provide misinformation about it.”

They underestimate what the American people are capable of, the president said.

“This generation of Americans is hammering into place the high-tech foundations of a clean energy age. Like the Americans who harvested the power of the atom, they are harvesting the power of the sun. That is what Americans do. You,” he said to the clean energy advocates in the summit’s audience, “are doing it every day, and I am going to be right there beside you.”

Solar and battery storage are commonly noted as the biggest threats — and opportunities — for the utility business model, but a new report shows that when consumers use their electricity may matter just as much to utilities as if they produce it themselves.

The potential for utility customers to dramatically reduce their energy consumption with less than a $1,000 dollar investment in home energy management devices could put a big dent in utilities’ bottom lines unless they figure out how to leverage the new technologies in a way that benefits both consumers and themselves

“The key to changing the balance of power between utilities and their customers is the customers' ability to control when and how they use electricity and for that demand flexibility is very important,” explained Rocky Mountain Institute (RMI) Principal James Mandel, co-author of the newreport "The Economics of Demand Flexibility; How “Flexiwatts” Create Quantifiable Value for Customers and the Grid."

Flexiwatts come from demand flexibility (DF), which is using “communication and control technology to shift electricity use across hours of the day.”

The premise is to use smart technology to move things like air conditioning, water heating, and electric vehicle charging to times when load is lower and electricity is cheaper. Devices now have the capability to control those functions and can be programmed to know when the lower price periods are.

“Demand flexibility need not complicate or compromise customer experience," RMI reports. “Technologies and business models exist today to shift load seamlessly while maintaining or even improving the quality, simplicity, choice, and value of energy services to customers.”

This is the third paper in RMI’s series on how solar PV and batteries are can lead to load defection by electricity users and, ultimately, grid defection by customers if utilities do not adjust.

The first analysis predicted increasing load defection, which is the growing use by customers of electricity they generate with their onsite distributed generation and save in their onsite storage.

The group also forecasted the possibility by the 2020s and 2030s of increasinggrid defection, which is customers moving to 100% self-supply. That could happen, the papers suggested, if utilities’ only response to falling costs for distributed energy resources [DERs] like solar PV plus batteries is increased electricity rates.

A utility business model that accurately values DERs "can potentially lower system wide costs while contributing to the foundation of a reliable, resilient, affordable, low-carbon grid of the future,” the load defection study explained. But if utilities’ plan for the future is just to build more infrastructure on both sides of the meter, their costs could be significant.

Customers are going to invest in DERs, Mandel said. If utilities don’t send the right price signals, customers will invest “in a way that serves their own best interests instead of a way that serves system-level best interests.”

The money in demand flexibility

To make demand flexibility work, customers must have some form of time varying pricing, Mandel said. It could be time-of-use pricing, which increases the price of electricity during the highest priced daily periods. Or it could be real-time pricing, which sets hourly electricity prices, or critical peak pricing, in which the grid operator reserves the right to increase the price sharply at certain peak hours.

“The best pricing is pricing that reflects utility costs,” Mandel said. “Real time pricing is an example of that. Demand charges sometimes are and sometimes aren’t.”

Technology specific pricing is shortsighted, he added. “Pricing consumers can use to their advantage should be an option for all customers.”

Customers can have demand flexibility with minimal investment, Mandel said in talking about the new analysis. With 65 million electricity customers already on some kind of time varying rates, the savings could be substantial.

The paper assumes only four shifts, all relatively uncontroversial, in electricity use: The use of smart thermostats and programmable timers on clothes dryers, EV chargers, and water heaters.

The total cost of such a system would likely be less than $1,000. With it, the analysis estimates, “demand flexibility could offer customers net bill savings of 10% to 40%.”

RMI modeled net bill savings in a variety of real-world utility scenarios. For the Commonwealth Edison real-time pricing scenario, consumers were predicted to save $250 million per year, a 12% savings. For the Salt River Project residential demand charge scenario, it was $240 million per year, a 41% savings. For a proposed Hawaii Electric Companies no-export-compensation for solar rate, it was $110 million per year, a 33% savings. And for Alabama Power’s avoided cost compensation for exported PV rate, $210 million per year, an 11% savings.

These bill reductions could put a dent in bottom lines across the electricity delivery system. But by adapting to what customers are likely to do anyway, utilities and system operators could save much more. They can “avoid $9 billion per year in traditional investments, including generation, transmission, and distribution,” the analysis shows.

Another $4 billion in savings is available from optimizing for hourly energy prices and from using demand flexibility for ancillary grid services. In all, the RMI researchers concluded that about $13.3 billion per year could be saved across the nation if demand flexibility practices took hold.

“The $13 billion per year saved from the projected $80-plus billion in annual grid investment is a conservative estimate," the paper reports, "because we analyze a narrow subset of flexible loads only in the residential sector, and we do not count several other benefit categories."

While U.S. electricity demand is flat to fading, the country is expected to spend an estimated $1.5 trillion over the next 15 years on grid infrastructure because of an increasingly “peaky” demand profile, explained RMI Transportation and Electricity Manager Jesse Morris. In the past, the solution has been fast-ramping fossil fuel “peaker” plants. More recently, there is some use of grid-scale storage.

“That is supply flexibility,” Morris said. “This paper says forget about supply flexibility and turn demand down with these kinds of smart devices. It is much cheaper. Our calculations show that with just the four devices, we can save 13% of that $1.5 trillion.”

Whether it is peaker plants or grid-scale storage, this is a cheaper asset than supply flexibility, Mandel added. “Grid investments are likely to raise prices and increase sunk costs, whether they are for traditional or renewable central station generation. Cutting investments with demand flexibility saves consumers money. Using both supply and demand flexibility is a smarter way to run a grid.”

Flexible demand and customer-sited solar

What utilities must recognize, the analysts said, is that while widespread solar-plus-storage is likely years off for many of them, demand flexibility is available to customers now and makes load defection an increased reality.

Demand flexibility is a critical third technology along with solar and battery storage, Mandell said. “For many of the things batteries can do for a customer, it can do them much cheaper.”

Demand charges are already common for commercial-industrial customers and are increasingly being imposed on residential customers, Mandell said. A residential demand charge imposes a bulk fee, often between $10 and $50, for every kilowatt the customer consumes during the highest 15 minute or 30 minute period of usage during the month.

Demand charges make battery storage an economic option even at today’s high prices and limited capacities. But demand flexibility can provide more of that same service today at a much lower cost.

“In our load defection analysis, there were timelines for customers to self-generate a portion of their electricity,” Mandel said. “Those timelines are accelerated by five to ten years if you include demand flexibility as a third resource for those customers.”

Where utilities are fighting solar PV with cuts to net energy metering or demand charges, demand flexibility makes it a more economic option because it allows the use of more of the solar kilowatts on site.

In the grid defection context — completely cutting the cord from the utility — demand flexibility dramatically lowers the cost in combination with PV and batteries.

In the load defection scenario, demand flexibility helps customers use as much as 90% of the solar energy-generated electricity on site.

“It is a way for a customer to manage their solar generation on site as opposed to relying on things like net metering to make their economics work out,” Mandell said.

“Instead of buying a battery, it is possible to make sure appliances turn on when the sun is shining and not when it is not,” Morris added. “That can be done with automation and no sacrifice of comfort. It provides the same service as the battery without the battery.”

The opportunity is available equally to vertically integrated investor owned utilities, deregulated transmission and distribution providers, and retail electricity providers in deregulated markets. The keys are offering rates that encourage changes in customer behaviors and to take advantage of the changes they make, the paper reports.

Utilities need to understand flexiwatts as a way to get to grid cost reductions, not just a threat to revenues. They can then construct rates reflecting utility marginal costs to “ensure that customer bill reduction (and thus, utility revenue reduction) can also lead to meaningful grid cost decreases.”

Having taken these steps, utilities should be able to see where demand flexibility will take them and “harness enabling technology and third-party innovation” to build customer-facing business models that target both lower bills for their customers and reduced sunk costs.

State regulators can support utilities in making a transition by pushing them to see demand flexibility as an opportunity instead of a threat, the paper explains. They can frame demand flexibility as “a potentially lower-cost alternative to a subset of traditional grid infrastructure investment.”

They can also support the introduction of new rate structures that balance “the potential complexity of highly granular rates against the large value proposition for customers and the grid” and facilitate utility-private sector partnerships likely to lead to innovation.

“Given the benefits,” the paper says, this “should be a near term priority.”

It is, Mandel added, “economic today with technology priced very conservatively. And the rate structures exist today. It is a big opportunity and a cost-effective opportunity.”
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Plug-in Hybrids: The Cars that will ReCharge America by Sherry Boschert: "Smart companies plan ahead and try to be the first to adopt new technology that will give them a competitive advantage. That’s what Toyota and Honda did with hybrids, and now they’re sitting pretty. Whichever company is first to bring a good plug-in hybrid to market will not only change their fortune but change the world."

Oil On The Brain; Adventures from the Pump to the Pipeline by Lisa Margonelli: "Spills are one of the costs of oil consumption that don’t appear at the pump. [Oil consultant Dagmar Schmidt Erkin]’s data shows that 120 million gallons of oil were spilled in inland waters between 1985 and 2003. From that she calculates that between 1980 and 2003, pipelines spilled 27 gallons of oil for every billion “ton miles” of oil they transported, while barges and tankers spilled around 15 gallons and trucks spilled 37 gallons. (A ton of oil is 294 gallons. If you ship a ton of oil for one mile you have one ton mile.) Right now the United States ships about 900 billion ton miles of oil and oil products per year."

NOTEWORTHY IN THE MEDIA:
NewEnergyNews would welcome any media-saavy volunteer who would like to re-develop this section of the page. Announcements and reviews of film, television, radio and music related to energy and environmental issues are welcome.

Review of OIL IN THEIR BLOOD, The American Decades by Mark S. Friedman

OIL IN THEIR BLOOD, The American Decades, the second volume of Herman K. Trabish’s retelling of oil’s history in fiction, picks up where the first book in the series, OIL IN THEIR BLOOD, The Story of Our Addiction, left off. The new book is an engrossing, informative and entertaining tale of the Roaring 20s, World War II and the Cold War. You don’t have to know anything about the first historical fiction’s adventures set between the Civil War, when oil became a major commodity, and World War I, when it became a vital commodity, to enjoy this new chronicle of the U.S. emergence as a world superpower and a world oil power.

As the new book opens, Lefash, a minor character in the first book, witnesses the role Big Oil played in designing the post-Great War world at the Paris Peace Conference of 1919. Unjustly implicated in a murder perpetrated by Big Oil agents, LeFash takes the name Livingstone and flees to the U.S. to clear himself. Livingstone’s quest leads him through Babe Ruth’s New York City and Al Capone’s Chicago into oil boom Oklahoma. Stymied by oil and circumstance, Livingstone marries, has a son and eventually, surprisingly, resolves his grievances with the murderer and with oil.

In the new novel’s second episode the oil-and-auto-industry dynasty from the first book re-emerges in the charismatic person of Victoria Wade Bridger, “the woman everybody loved.” Victoria meets Saudi dynasty founder Ibn Saud, spies for the State Department in the Vichy embassy in Washington, D.C., and – for profound and moving personal reasons – accepts a mission into the heart of Nazi-occupied Eastern Europe. Underlying all Victoria’s travels is the struggle between the allies and axis for control of the crucial oil resources that drove World War II.

As the Cold War begins, the novel’s third episode recounts the historic 1951 moment when Britain’s MI-6 handed off its operations in Iran to the CIA, marking the end to Britain’s dark manipulations and the beginning of the same work by the CIA. But in Trabish’s telling, the covert overthrow of Mossadeq in favor of the ill-fated Shah becomes a compelling romance and a melodramatic homage to the iconic “Casablanca” of Bogart and Bergman.

Monty Livingstone, veteran of an oil field youth, European WWII combat and a star-crossed post-war Berlin affair with a Russian female soldier, comes to 1951 Iran working for a U.S. oil company. He re-encounters his lost Russian love, now a Soviet agent helping prop up Mossadeq and extend Mother Russia’s Iranian oil ambitions. The reunited lovers are caught in a web of political, religious and Cold War forces until oil and power merge to restore the Shah to his future fate. The romance ends satisfyingly, America and the Soviet Union are the only forces left on the world stage and ambiguity is resolved with the answer so many of Trabish’s characters ultimately turn to: Oil.

Commenting on a recent National Petroleum Council report calling for government subsidies of the fossil fuels industries, a distinguished scholar said, “It appears that the whole report buys these dubious arguments that the consumer of energy is somehow stupid about energy…” Trabish’s great and important accomplishment is that you cannot read his emotionally engaging and informative tall tales and remain that stupid energy consumer. With our world rushing headlong toward Peak Oil and epic climate change, the OIL IN THEIR BLOOD series is a timely service as well as a consummate literary performance.

Review of OIL IN THEIR BLOOD, The Story of Our Addiction by Mark S. Friedman

"...ours is a culture of energy illiterates." (Paul Roberts, THE END OF OIL)

OIL IN THEIR BLOOD, a superb new historical fiction by Herman K. Trabish, addresses our energy illiteracy by putting the development of our addiction into a story about real people, giving readers a chance to think about how our addiction happened. Trabish's style is fine, straightforward storytelling and he tells his stories through his characters.

The book is the answer an oil family's matriarch gives to an interviewer who asks her to pass judgment on the industry. Like history itself, it is easier to tell stories about the oil industry than to judge it. She and Trabish let readers come to their own conclusions.

She begins by telling the story of her parents in post-Civil War western Pennsylvania, when oil became big business. This part of the story is like a John Ford western and its characters are classic American melodramatic heroes, heroines and villains.

In Part II, the matriarch tells the tragic story of the second generation and reveals how she came to be part of the tales. We see oil become an international commodity, traded on Wall Street and sought from London to Baku to Mesopotamia to Borneo. A baseball subplot compares the growth of the oil business to the growth of baseball, a fascinating reflection of our current president's personal career.

There is an unforgettable image near the center of the story: International oil entrepreneurs talk on a Baku street. This is Trabish at his best, portraying good men doing bad and bad men doing good, all laying plans for wealth and power in the muddy, oily alley of a tiny ancient town in the middle of everywhere. Because Part I was about triumphant American heroes, the tragedy here is entirely unexpected, despite Trabish's repeated allusions to other stories (Casey At The Bat, Hamlet) that do not end well.

In the final section, World War I looms. Baseball takes a back seat to early auto racing and oil-fueled modernity explodes. Love struggles with lust. A cavalry troop collides with an army truck. Here, Trabish has more than tragedy in mind. His lonely, confused young protagonist moves through the horrible destruction of the Romanian oilfields only to suffer worse and worse horrors, until--unexpectedly--he finds something, something a reviewer cannot reveal. Finally, the question of oil must be settled, so the oil industry comes back into the story in a way that is beyond good and bad, beyond melodrama and tragedy.

Along the way, Trabish gives readers a greater awareness of oil and how we became addicted to it. Awareness, Paul Roberts said in THE END OF OIL, "...may be the first tentative step toward building a more sustainable energy economy. Or it may simply mean that when our energy system does begin to fail, and we begin to lose everything that energy once supplied, we won't be so surprised."

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